Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer. Thus, the porous layer forms a reservoir, that is, a volume in which hydrocarbons accumulate. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections or “joints” referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the bore of the well. This fluid serves to lubricate the bit. The drilling mud also carries cuttings from the drilling process back to the surface as it travels up the wellbore. As the drilling progresses downward, the drill string is extended by adding more joints of pipe.
A modern oil well typically includes a number of tubes extending wholly or partially within other tubes. That is, a well is first drilled to a certain depth. Large diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. After the initial section has been drilled, cased, and cemented, drilling will proceed with a somewhat smaller wellbore. The smaller bore is lined with somewhat smaller pipes or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A well may include a series of smaller liners, and may extend for many thousands of feet, commonly up to and over 25,000 feet.
The liners are cemented in the wellbore as the well is constructed. That is, the liner necessarily is smaller than the bore in which it is installed. The gap between the liner and the wellbore is referred to as the annulus, and it is filled with cement after the liner has been installed. The cement helps secure the liner in the wellbore and protect it against corrosion and erosion. It also supports the borehole walls from collapse. If fluids will be produced through the liner, cement also helps ensure more precise control over stimulation processes, such as fracturing and acidizing.
Most importantly, the cement is intended to form a continuous sheath, that is, a complete seal around the liner. If the liner leaks, the cement sheath will help ensure that fluids flowing through the liner do not contaminate the surrounding formation, and especially water-bearing formations. The cement sheath also ensures that hydrocarbons and other fluids in the formation are not able to migrate to other parts of the formation or to the surface.
The liner is cemented in the wellbore by injecting a cementitious, settable slurry down the liner and allowing it to flow up the annulus. The cement then is allowed to set, that is, solidify and harden into what hopefully will be a continuous seal throughout the annulus. There are a number of challenges, however, in ensuring that the sheath is continuous and that a complete seal is established between the bore and liner. Some issues arise from the chemical and physical nature of the cement slurry and how it interacts with other fluids in the well or the formation. The position of a liner in the bore also can create significant impediments to forming a complete seal.
That is, oil wells are commonly depicted as extending straight down into the earth with a tube running right down the middle of the bore. The truth is far from that. Because it is formed with a rotating drill bit, the bore will tend to corkscrew as it is extended. Moreover, in order to increase production, the bore commonly will be deviated from a nominal vertical bearing to extend it along, rather than through a hydrocarbon-beating formation. So-called “horizontal” wells constitute most of the wells being drilled in the United States today.
A liner, therefore, will not necessarily be centered within a wellbore. It may tend to rest against the side of a bore, especially in horizontal extensions. A cement slurry may not be able to flow into the area where a liner rests against the borehole. Thus, when set, voids may be left in the cement sheath, or it may have thin, weak portions. Fluids from the formation may be able to migrate from one area of the formation to another or may even reach the surface.
In an effort to mitigate such problems, a liner typically will be provided with centralizers. The centralizers are intended to maintain a minimum clearance between the liner and the bore, while at the same time providing paths which allow cement slurry to flow past them. “Bow-spring” centralizers are one common type of centralizer. They have a pair of relatively short sleeves that fit around the outside of a liner. A number of relatively stiff, narrow bow springs extend between the sleeves. The bow springs curve away from the liner and keep the liner spaced from the walls of the bore. The springs are spaced angularly around the circumference of the sleeves so that cement slurry can flow around and through the centralizer.
“Spiral-blade” centralizers are another common type. They incorporate a single longer sleeve. The sleeve has raised, rounded blades that extend along the sleeve in a loose helix. The blunt blades maintain clearance with the bore while providing channels through which cement may flow. Centralizers, therefore, can greatly reduce or eliminate contact between a liner and the bore, and help ensure that the cement sheath will have sufficient thickness throughout the annulus to provide an effective seal.
Centralizers may be mounted on a liner in a fixed position. For example, U.S. Pat. Pub. No. 2013/0160993 of J. Davilla et al. discloses a spiral-blade centralizer that is fixedly mounted on a liner. It generally comprises a body and a pair of wedge rings. The body is generally cylindrical and fits around a liner. Blunt blades are provided around its circumference to keep the liner spaced from the bore and provide channels for cement flow. Each end of the centralizer body has internal threads. The threads are opposed. That is, the threads on one end of the body are right-hander and those at the other end are left-handed. The internal threads on the body engage external threads on a tapered surface of the wedge rings. Thus, the body may be rotated to draw the wedge rings together. As they draw together, teeth on the inner surface of the wedge rings bite into the liner, securing the centralizer in place.
Providing a centralizer with some freedom of movement, however, can make it much easier to run a liner into a well. Thus, other centralizers, including bow-spring and spiral-blade type centralizers, are mounted such that they are free to rotate and travel a certain distance along a liner. Sliding centralizers are widely available on the market, including slip-on bow-spring and spiral-blade centralizers distributed by Top-Co, Houston, Tex., and MSIS-B bow spring centralizers available from Weatherford. Movement of the centralizer along a liner will be limited by what are referred to as thrust or stop collars. A stop collar will be placed above and below the centralizer as a joint of liner is run into the well. The stop collars are securely mounted to the liner to provide mechanical stops limiting travel of the centralizer along the liner.
Stop collars may simply comprise a collar which is slid on a liner and secured in place with set screws. Other designs utilize a hinged collar or a split collar. The collar is opened to place it around a liner. The ends then are brought together and latched or otherwise secured. Such designs may have metal gripping features which bite into the liner, or they may have an elastomeric layer concentrically disposed within the collar. Some designs incorporate both metal gripping features and elastomers, such as the stop collars disclosed in U.S. Pat. No. 3,652,138 to C. Collett. Other designs rely on a layer of swellable elastomer disposed on the inside surface of the collar, such as those disclosed in U.S. Pat. No. 7,942,199 to P. Angman. The collar is dipped into an activating solution and then slipped onto the liner. The elastomer swells and grips the liner.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved systems and apparatus for mounting stop collars and other tool assemblies in a fixed position on liners and other tubular members. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.